Process for removing and recovering h2s from a gas stream by cyclic adsorption

ABSTRACT

A process for altering the composition of a feed gas containing H 2 S equivalents is disclosed. The process comprises (a) contacting the feed gas with a solid adsorbent at a temperature of 250-500° C., to obtain a loaded adsorbent, (b) purging the loaded adsorbent with a purge gas comprising steam, thus producing a product stream which typically contains substantially equal levels of CO 2  and H 2 S. The process further comprises a step (c) of regenerating the purged adsorbent by removal of water. The adsorbent comprises alumina and one or more alkali metals, such as potassium oxides, hydroxide or the like.

The present invention is in the field of removal of sour gases byadsorption, for example from syngas or Claus tail gas. Thus, theinvention relates to an improved process for the selective removal ofhydrogen sulphide (H₂S), and optionally further inorganic sulphidecomponents such as carbonyl sulphide (COS) and carbon disulphide CS₂,from a gas stream by adsorption, particularly a gas stream comprisingCO₂ and H₂S in a molar ratio above 0.5, and for recovering the inorganicsulphur as H₂S allowing valorisation thereof.

BACKGROUND

Hydrogen sulphide removal from sour gas streams is of great industrialimportance, as such gases are the main known source of H₂S. An importantsource of sour gases is synthesis gas (syngas) containing hydrogen,carbon monoxide, carbon dioxide and further components including H₂S, orits subsequent product obtained by water gas shift (WGS) reaction, suchas described in WO 2010/059052. The WGS reaction produces H₂ and CO₂while H₂S can be present in the feed stream. In Sorbent-enhanced WGS,CO₂ and H₂S are adsorbed onto an adsorbent such as alkali-promotedhydrotalcite and subsequently simultaneously desorbed from theadsorbent. As such, CO₂ and H₂S end up in the same effluent stream,restricting efficient reuse or requiring purification of such gaseousmixtures.

Known techniques for selective removal of H₂S from a sour gas containingCO₂ include physical, chemical and hybrid scrubbing techniques and metaloxide scavenging. Chemical scrubbing involves the use of amine-basedsolvents that chemically react with sour gases such as H₂S and CO₂.Physical solvents involve e.g. methanol or glycol, using the physicaldissolution of the acid gases obeying Henry's law, and hybrid solventscombining the best of both chemical and physical solvents. Because thesesolvents favour H₂S over CO₂ only slightly, H₂S enrichment yields arerelatively poor, which renders this technique unsuitable for selectiveremoval of H₂S from a CO₂-rich, H₂S-lean stream.

EP2407227 provides a method for separating H₂S from a sour syngas streamdifferent from the aforementioned liquid absorption processes using apressure swing adsorption system (PSA) to produce a stream enriched inCO₂ and H₂S, after which H₂S is removed for instance by using a packedbed of ZnO that would be disposed of and replaced when saturated withH₂S, or silica gels, impregnated activated carbons and/or molecularsieves. In one embodiment, steam is used to heat the bed that has beenloaded with H₂S to help removing said H₂S. Scavengers, such as Zn-,Zn/Cu- or Fe-based scavengers, bind H₂S irreversibly and thus cannoteconomically deal with feeds comprising relatively high amounts of H₂S,such as typically 200 ppm H₂S or even only 100 ppm H₂S. Large scaleprocesses or H₂S levels above about 100 ppm require frequent replacementof the scavenger bed, which is usually too expensive to be economicallyfeasible.

WO 2013/019116 discloses a process for selectively removing acidicgaseous components, in particular carbon dioxide (CO₂) and hydrogensulphide (H₂S), from an adsorbent which has adsorbed these gaseouscomponents from a feed gas. It involves a CO₂ purge to replace the H₂Sand a subsequent H₂O purge to remove the CO₂. The process is well suitedfor a Sorption-Enhanced WGS process, which produces H₂ and CO₂, andwherein (small) amounts of H₂S may be present. H₂S and CO₂ aresubsequently separately separated from H₂.

There remains a need for enriching a gaseous stream in H₂S from a(CO₂-rich, H₂S-lean) feed stream that comprises intermediate amounts ofH₂S (e.g. 100-10,000 ppm), for which scavenger and scrubbing techniquesare unsuited. Existing H₂S enrichment techniques as described above canonly achieve about one order of magnitude enrichment at high H₂Sconcentrations, and two orders of magnitude increase in concentrationfrom low H₂S concentrations, for which a marked improvement is required.

SUMMARY OF THE INVENTION

The invention relates to a process for contacting a feed gas comprisingH₂S and CO₂ to an adsorbent material for altering the composition of thegas, and is particularly suited for selectively removing H₂S from a feedgas which is preferably CO₂-rich and H₂S-lean, as defined further below,or in other words for enriching such feed in H₂S. At the same time, aCO₂-containing stream may be produced which is low in H₂S. In theprocess of the invention, H₂S equivalents, including H₂S, carbonylsulphide (COS) and carbon disulphide (CS₂), are preferentially adsorbedonto the sorbent, followed by purging the adsorbent with a purging gascomprising steam, which gives rise to desorption of H₂S. In view of sucheffective desorption with steam, intermediate CO₂ rinses are renderedsuperfluous.

The process according to the invention is thus capable of selectivelyremoving hydrogen sulphide from a gas and of realising up to threeorders of magnitudes H₂S concentration increase compared to the feedstream. To that end, the inventors found that selective retention of H₂S(and/or equivalents thereof) could be improved by conditioning the waterconcentrations at contact between feed gas and solid adsorbent forselectively adsorbing H₂S (and/or equivalents thereof). This can beachieved by either drying the solid adsorbent or providing a gaseousfeed low in H₂O, or, preferably, both.

The process according to the invention thus comprises:

-   (a) contacting a feed gas containing H₂S equivalents, CO₂ and    optionally H₂O, wherein the molar ratio of H₂O to H₂S equivalents is    within the range of 0-(5+X), with a solid adsorbent at elevated    temperature, to obtain a loaded adsorbent and a first product gas;-   (b) purging the loaded adsorbent with a purge gas comprising steam    to obtain a second product gas.

Herein, the feed gas and/or the purge gas comprises a reducing agentsuch as hydrogen and the adsorbent comprises alumina and one or morealkali metals. In the molar ratio of H₂O to H₂S equivalents, which is inthe range of 0-(5+X), X is defined as:

$X = {\sum\frac{n_{i}\lbrack {H_{2}S\mspace{14mu} {equivalent}} \rbrack_{i}}{\lbrack {H_{2}S{\mspace{11mu} \;}{equivalents}} \rbrack}}$

wherein [H₂S equivalents] indicates the total concentration (typicallyin ppm) of H₂S equivalents, [H₂S equivalent]_(i) indicates theconcentration (typically in ppm) of a particular H₂S equivalent i andn_(i) indicates the amount of water molecules n consumed when said H₂Sequivalent i is converted to H₂S.

The term “H₂S equivalents” as used herein denotes H₂S and its gaseous orvolatile sulphur equivalents which contain sulphur (formally) inoxidation state −2, such as carbonyl sulphide (COS) and carbondisulphide (CS₂). H₂S equivalents are preferably selected from the groupconsisting of H₂S, COS, CS₂ and mixtures thereof. In this respect, COSand CS₂ are referred to as equivalents of H₂S. The term “H₂Sequivalents” does not includes higher valence sulphur species such assulphur dioxide

Preferably, the process comprises a further step (c) wherein the purgedadsorbent is dried, after which the adsorbent is capable of adsorbingH₂S equivalents again. As such, the adsorbent is regenerated andavailable for reuse in step (a) of the process again. The terms“adsorbent drying” and “adsorbent regeneration” are usedinterchangeably.

It was found that, advantageously, carbonyl sulphide (COS) and carbondisulphide (CS₂), if present in the feed gas, are removed together withthe H₂S when using the adsorbent of the present invention, not requiringa prior hydrolysis to H₂S of these components. With the purging of step(b), all original H₂S equivalents (H₂S, COS and CS₂ and the like) arereleased essentially as H₂S only. The H₂S enriched effluent (secondproduct gas) is extraordinarily high in H₂S content, thus rendering theeffluent useful for further application in e.g. Claus sulphurproduction.

DETAILED DESCRIPTION

The invention relates in a first aspect to a process for altering thecomposition of a gas containing H₂S equivalents and CO₂. In a secondaspect, the invention relates to a Claus process wherein the processaccording to the first aspect is implemented. A third aspect of theinvention concerns a system designed to implement the processesaccording to the first and second aspects of the invention, comprising aClaus unit and an adsorption module equipped with a bed of adsorbentcomprising alumina and one or more alkali metals.

Process for Altering the Composition of a Gas

The first aspect of the invention more specifically relates to a processfor selectively recovering H₂S from a feed gas or enriching said gas inH₂S, wherein said feed gas comprises CO₂ and H₂S equivalents, preferablyin a molar ratio of H₂S equivalents to CO₂ of less than 2, andoptionally water, wherein the molar ratio of H₂O to H₂S equivalents isin the range of 0-(5+X). The process comprises (a) contacting the feedgas with a solid adsorbent, at a temperature of 250-500° C., to obtain aloaded adsorbent (the loading including H₂S) and a purified firstproduct gas, (b) purging the loaded adsorbent with a purge gascomprising steam to obtain a gas enriched in H₂S compared to the feedgas, and preferably (c) drying the purged adsorbent. The adsorbentcomprises alumina and one or more alkali metals. The alkali metals arein particular in the form of their oxides, hydroxides, carbonates,sulphides, hydrosulphides, hydroxyl-carbonates, thiols, formates,hydroxyformates or the like, the (hydro)sulphides possibly being formedin the course of the adsorption process.

In the context of the present invention, the composition of gaseousmixtures is given in percentages (%) or ppm values. Unless indicatedotherwise, these always refer to mole percentages or molar ratios. Inthe context of the invention, the term “gas” refers to any pure compoundor mixture of compounds in the gas phase. A gas should be gaseous at theprocessing conditions, i.e. at least at a temperature of 250-500° C. andat a pressure of 1-15 bar, even though higher or lower pressures may befeasible as well. Under such conditions, water is in gaseous form, whichmay also be referred to as steam. Hence, the terms “water” (or “H₂O”)and “steam” are used interchangeably in the context of the presentinvention. Solid compositions, such as for the adsorbent, are typicallygiven in wt % (weight percentage) unless indicated otherwise. Theadsorbent is solid at the processing conditions.

The feed gas may be referred to as “sour gas”, which is a term of artfor a gas containing at least 4 ppm hydrogen sulphide and/or equivalentsthereof (see e.g. http://naturalgas.org/naturalgas/processing-ng/). Sourgases may be natural gases or may for example be generated duringindustrial processes (e.g. gasification of coal, biomass or mixturesthereof, e.g. the tail gas of a Claus process). The “sour gas” in thecontext of the invention contains H₂S equivalents, CO₂ and optionallywater (steam). However, large amounts of water hamper selectiveadsorption of H₂S equivalents to the adsorbent, so water should bepresent in the feed stream in a molar ratio of H₂O to H₂S equivalents inthe range of 0 to (5+X), preferably 0 to (2+X), even more preferably 0to (1+X), most preferably 0 to 1. Herein, X is a constant, the value ofwhich depends on the type and amount of equivalents of H₂S present inthe feed gas, taking into account the consumption of H₂O duringconversion of such equivalent to H₂S. Each equivalent of H₂S allows fora different maximal steam content. X is further defined below. Herein, amolar ratio of 0 (zero) refers to the complete absence of steam. Inabsolute terms, the water (steam) level in the feed gas is preferablybelow 20%, more preferably below 5%, even more preferably below 2%, mostpreferably below 0.5%. Although it is preferred that the feed gas iscompletely dry without any water present, the process according to thefirst aspect of the invention runs sufficiently effective even when aminor amount of water is present. Typically, the molar ratio of H₂O toH₂S equivalents may be at least 0.001 or at least 0.01 or at least 0.1or even at least 0.5, or in absolute terms, the feed gas may contain atleast 50 ppm water or at least 100 ppm water or even at least 500 ppmwater. This implies that source gases containing appreciable levels ofwater, such as Claus tail gases, may have to be dried, e.g. bycondensation, adsorption, absorption or other conventional methods, tobelow the above levels, before being subjected to the process of theinvention.

The feed gas comprises H₂S equivalents as defined herein. In the contextof the present invention, the term “H₂S equivalents” denotes H₂S and itsgaseous or volatile sulphur equivalents which contain sulphur (formally)in oxidation state −2, such as carbonyl sulphide (COS) and carbondisulphide (CS₂). H₂S equivalents preferably comprise H₂S, COS and/orCS₂, more preferably are selected from the group consisting of H₂S, COS,CS₂ and mixtures thereof. In this respect, COS and CS₂ are referred toas equivalents of H₂S. The term “H₂S equivalents” does not includehigher valence sulphur species such as sulphur dioxide. Typically, butnot mandatorily, the H₂S equivalents include H₂S as such, andpreferably, they also include COS and/or CS₂. The combined content ofH₂S equivalents in the feed gas typically ranges from 5 ppm to 5%(50,000 ppm), preferably 10-25,000 ppm (2.5%), more preferably100-10,000 ppm, even more preferably 150-5000 ppm, most preferably200-2000 ppm. It is noted that COS and CS₂ were found to be adsorbed instep (a) and converted to H₂S upon steam purging of step (b). Regardlessof the type of H₂S equivalent(s) present in the feed gas, the secondproduct stream, i.e. the effluent of step (b), will contain H₂S as solesulphur species. COS and CS₂, as well as H₂S itself, are desorbed asH₂S. These species are thus considered equivalent to H₂S.

Without being bound to a theory, it is expected that during theoperating conditions, two equilibria are established for which theadsorbent acts as a catalyst. These two equilibria are:

COS+H₂O

H₂S+CO₂   (1)

CS₂+2 H₂O

2 H₂S+CO₂   (2)

Upon breakthrough, i.e. complete loading of the adsorbent with H₂Sequivalents, H₂S equivalents end up in the first product gas, since theycan no longer be adsorbed. The inventors found that regardless ofwhether H₂S, COS or CS₂ (or mixture thereof in any ratio) is present inthe feed gas, H₂S and COS are observed in the first product gas in theirequilibrium concentrations according to equilibrium (1). No CS₂ isobserved, since equilibrium (2) is completely shifted to the right underthe processing conditions, i.e. equilibrium concentration of CS₂ is(close to) 0.

As is clear from equilibrium (1), one molecule of COS is equivalent toone molecule of H₂S, wherein one molecule of H₂O is consumed. Thus, foreach molecule (or mole) of COS present in the feed stream, oneadditional molecule (or mole) of H₂O may be present therein. Likewise,as is clear from equilibrium (2), one molecule of CS₂ is equivalent totwo molecules of H₂S, wherein two molecules of H₂O are consumed. Thus,for each molecule (or mole) of CS₂ present in the feed stream, twoadditional molecules (or moles) of H₂O may be present therein. For thisreason, the allowable water content in the feed gas employs the factorX. Thus, the ratio of H₂O to H₂S equivalents is in the range of 0-(5+X),preferably 0-(2+X), even more preferably 0-(1+X), wherein X is definedas:

$X = {\sum\frac{n_{i}\lbrack {H_{2}S\mspace{14mu} {equivalent}} \rbrack_{i}}{\lbrack {H_{2}S{\mspace{11mu} \;}{equivalents}} \rbrack}}$

Herein, [H₂S equivalents] indicates the total concentration (typicallyin ppm) of H₂S equivalents, [H₂S equivalent]_(i) indicates theconcentration (typically in ppm) of a particular H₂S equivalent i andn_(i) indicates the amount of water molecules n consumed when said H₂Sequivalent i is converted to H₂S. Thus, n_(i)=0 for i=H₂S, n_(i)=1 fori=COS and n_(i)=2 for i=CS₂. For the preferred situation where the H₂Sequivalents are selected from H₂S, COS, CS₂ and mixtures thereof, Xsimplifies as:

$X = \frac{\lbrack{COS}\rbrack + {2\lbrack {CS}_{2} \rbrack}}{\lbrack {H_{2}S\mspace{14mu} {equivalents}} \rbrack}$

Herein, [COS] and [CS₂] indicate the concentration (typically in ppm) ofCOS and CS₂ respectively, and [H₂S equivalents]=[H₂S]+[COS]+[CS₂]. Incase the H₂S equivalents only contain H₂S, i.e. the feed gas does notcomprise detectable amounts of other H₂S equivalents, X=0. Since Xdefines the upper limit of the allowable range of H₂O to H₂S in the feedgas, X may not exceed the above-defined values, as that would render thefeed gas too wet for effective performance of the process according tothe first aspect of the invention. For example, one molecule of COSrequires one molecule of H₂O (or consumes one molecule of H₂O) forconversion to one molecule of H₂S, so n_((COS))=1. Thus, when the feedgas comprises COS as the only H₂S equivalent, X=1 and the maximalallowable water content of the feed gas defined as the ratio of H₂O toH₂S equivalent is 6. Similarly, a 9 to 1 H₂S to COS mixture gives X=0.1and results in a maximal allowable ratio of H₂O to H₂S equivalent of5.1. Pure CS₂ gives X=2 and results in a maximal allowable ratio of H₂Oto H₂S equivalent of 7. In one embodiment, X=0 and the H₂O to H₂Sequivalents ratio is 0-5, preferably 0-2, more preferably 0-1.

The feed gas may also be referred to as a “CO₂-rich, H₂S-lean” feed gas,meaning that the molar ratio of H₂S equivalents to CO₂ is preferablybelow 1, more preferably below 0.1, even more preferably between 0.0001and 0.05, most preferably in the range of 0.001-0.02 or even 0.002-0.01.CO₂ levels of the feed gas may vary greatly without negatively affectingthe process. They typically range from 100 ppm to 99%, preferably atleast 500 ppm and up to 95%, more preferably from 0.5% (5000 ppm) up to50%, most preferably 3-25%.

In addition to the acidic or “sour” species, other, essentiallynon-acidic, components may also be present, including hydrogen, carbonmonoxide, hydrocarbons or other fuel gases, water, as well as any amountof inert gaseous species such as nitrogen, noble gases (e.g. helium,argon) and the like. The level of oxygen should preferably be low, e.g.below 2%, preferably below 0.5% or even below 0.1% (1000 ppm). Thepresence of higher levels of O₂ is undesirable, as this creates anoxidizing environment wherein SO₂ may be formed. Thus, the presence ofO₂ counteracts the effect of the reducing agent which is preferablypresent in the feed gas. As discussed, the water content should also bekept low.

The feed gas typically further comprises a reducing agent. Although lesspreferred, the feed gas could also be free of a reducing agent, in whichcase it might be required to periodically regenerate the bed ofadsorbent material. Such bed regeneration could be effected by reductionusing a reducing agent as defined herein, optionally assisted by heatingthe bed to aid the decomposition of deactivating components. Thereducing agent in the context of the present invention is a gaseousspecies capable of reducing oxidised species, typically capable ofpreventing the oxidation of H₂S to SO₂ or sulphates, under the processconditions. During the purging of step (b), the adsorbed H₂S species arein contact with great excess of H₂O molecules, which may oxidise H₂S(and/or equivalents thereof) to SO₂ or even sulphates, under the processconditions. A reducing environment suppresses such oxidation. Theinventors surprisingly found that the presence of a reducing agent inthe feed gas, i.e. during the contacting of step (a), suppresses suchoxidation during step (b). Alternatively, the purging gas may comprisethe reducing agent, as described further below, which also suppressessuch oxidation. If no reducing agent is present in both the feed gas andthe purging gas, significant amounts of the adsorbed H₂S are convertedto sulphates during step (b), which are not capable of desorbing fromthe adsorbent. Preferably, the reducing agent is selected from H₂ and/orCO, more preferably the feed gas comprises at least H₂ as reducingagent. The feed gas preferably comprises 0.1-50%, more preferably0.5-30%, most preferably 1-20% reducing agent, most preferably H₂. Thepresence of a reducing agent thus suppresses the formation of sulphateson the adsorbent, for which the adsorbent may act as catalyst. Thepresence or formation of SO₂ is undesirable, since it is adsorbed duringstep (a) and when contacted with steam during step (b), SO₂ reacts tosulphate which is not readily desorbed upon purging with steam. Thus,the presence or formation of SO₂ and/or the absence of a reducing agentdecreases the adsorption capacity of the adsorbent.

It is thus also preferred that the feed gas does not contain appreciablelevels of SO₂ (or other sulphur oxides, together referred to as SO_(x));preferably it contains less than 0.5% (5000 ppm), more preferably lessthan 0.05% (500 ppm), most preferably less than 50 ppm. In a particularembodiment, the feed gas contains substantially no (i.e. less than 10ppm) of SO₂. In an especially preferred embodiment, the content of CO₂and H₂ is substantially equal (ratio between 1:2 and 2:1). CO may alsobe present, e.g. in an amount of 0.05-30%, more preferably 0.1-20%, mostpreferably 0.5-10%. Since the feed gas preferably contains syngas, it ispreferred that the level of H₂ and CO is substantially equal, i.e. molarratio H₂:CO is 1:2-2:1.

According to a preferred embodiment of the invention the process is usedfor the separation H₂S from sour natural gas, syngas (e.g. general,biomass-derived or coal-derived), Claus tail gas, H₂S-containing gaseousfuels, tail gas of hydrodesulphurisation, wherein sulphur species areremoved from gaseous streams (e.g. of petroleum products of refineries)by hydrogenation to H₂S. Such gases are preferably used as feed gas instep (a) of the process according to the invention. H₂S is readilyseparated from H₂S-containing gaseous fuels by the process according tothe invention, wherein the fuel depleted in H₂S is obtained as firstproduct gas. The adsorbent according to the invention does not adsorbhydrocarbon species, which thus leads to no loss in fuel during theadsorption of step (a). Amine scrubbing to remove sulphur species willalways lead to some removal of hydrocarbons, thus leading to fuel loss.Preferred feed gases include H₂S-containing gaseous fuels, syngases andClaus tail gases, in particular, syngases and Claus tail gases havingtypical compositions as given in Table 1 below. Herein “inert” gasescomprise nitrogen, noble gases and the like and the values for H₂Sinclude COS and CS₂. Most preferably, a Claus tail gas is used as feedgas, since the process according to the first aspect of the invention isespecially suitable to be incorporated with a Claus process. In thisrespect, it is especially preferred that the second product gas is usedas incoming gas for a Claus process. These aspects of the invention arediscussed further below.

In one embodiment, the feed gas has been pre-treated prior to beingsubjected to step (a) of the process according to the first aspect ofthe invention. Pre-treatment may be employed to lower the H₂O contentand/or the SO₂ content (or the SO_(x) content). Pre-treatment to lowerthe SO₂ or SO_(x) content is particularly preferred for Claus tail gasesand typically involves subjecting a SO_(x)-containing gas to ahydrogenation-hydrolysis step, as known to the art, to convert SO_(x) toH₂S. SO_(x) can also be lowered by scrubbing with an alkaline solutionfollowed by chemical reduction, e.g. using hydrogen, or by biologicalreduction, e.g. using bacteria of the genera Desulfovibrio,Desulfobacterium, Desulforomonas or the like. Alternatively, the SO₂ orSO_(x) content of the Claus tail gas can be lowered by tuning of theoxidation step(s) in the Claus process itself.

Pre-treatment to lower the H₂O content is particularly preferred in casethe H₂O content of a potential feed gas is too high, i.e. the molarratio of H₂O to H₂S equivalents is above (5+X). Where necessary, the H₂Olevel of the feed gas is lowered e.g. by cooling and/or pressurisationresulting in condensation of water or by other conventional methods suchas absorption or adsorption. Since drier feed gases give rise toincreased H₂S adsorption capacity of the adsorbent, it is preferred thatpre-treatment to lower the H₂O content includes a measure to lower theH₂O level to well below 1%. Such a measure may include a glycol rinse ofthe feed gas and/or contacting the feed gas with molecular sieves,optionally after one or more of the above-mentioned techniques.Alternatively or additionally, the H₂O content may be lowered byselective permeation of water through a membrane (e.g. by vacuumpermeation). Feed gases pre-treated as such are especially suitable tobe used as feed gas for the process according to the first aspect of theinvention, in view of their extremely low or even negligible watercontent. Pre-treatment to lower the H₂O level is also referred to asdrying or “pre-drying”.

TABLE 1 Typical gaseous compositions (in vol %) H₂ CO CO₂ H₂O CH₄ inertH₂S Syngas general 25-45 20-60 5-25 2-30 0-15 0.5-5  0.01-1 Biomass-derived 30-45 20-30 15-25  2-10 5-15 2-5  0.002-0.05Coal-derived 25-30 30-60 5-15 2-30 0-5  0.5-5  0.2-1 Claus tail gas0.2-5  0-1 1-10 15-50  0-1  40-75 0.5-5

The adsorbent to be used in the process of the invention is capable ofadsorbing H₂S and comprises a mixture of inorganic (hydr)oxidescomprising a trivalent metal oxide, especially alumina (aluminum oxideor hydroxide). Instead or in addition to aluminum, other metals capableof adopting a trivalent state may be present, such as Fe, Mn, Cr, Ti,Pd, Ce and Zr. Apart from being highly effective in the processaccording to the invention, the use of alumina in the adsorbentaccording to the invention has further advantages. First of all,aluminas are highly stable towards reducing condition that occur duringthe process according to the invention, in contrast to e.g. tin oxidebased materials. Also the hydrothermal stability (i.e. the inertnesstowards steam at high temperature) of aluminas, especiallyhydrotalcites, is excellent, thus preventing sintering of the adsorbentmaterial under the process conditions. Sintering is especiallydisadvantageous, since it reduces the surface area of the adsorbent andthus the adsorbent capacity. The alumina of the adsorbent according tothe invention is promoted with, i.e. contains, one or more alkalimetals, in ionic form, e.g. as their oxides, hydroxides, carbonates, orin situ, sulphides and/or hydrosulphides. Preferably the adsorbentcomprises one or more alkali metal oxides, hydroxides and/or carbonates,more preferably one or more alkali metal oxides or carbonates. Anyalkali metal can be used, including Li, Na, K, Rb and Cs. Preferredalkali metals are Na and K, most preferably K is used as alkali metal.The alkali metal content of the adsorbent is preferably 2-30 wt %, morepreferably 5-25 wt %, most preferably 10-15 wt %.

The adsorbent may advantageously further comprise one or more divalentmetal oxides, hydroxides, carbonates, sulphides and/or hydrosulphides.The divalent metals can be an alkaline earth metal (Mg, Ca, Sr, Ba) orCo, Ni, Cu, Zn, Cd, Pb. Preferred divalent metals are Mg, Ca, Sr, Ba,Zn, Ni and Cu. More preferably, the adsorbent comprises calcium oxideand/or magnesium oxide and/or zinc oxide. In particular, the adsorbenthas an atomic ratio of divalent metals (especially one or more of Mg,Ca, Zn) to Al of between 0 and 3, preferably between 0.05 and 1.5, e.g.between 0.11 and 1.0, and an atomic ratio of alkali metal (especially Naand/or K) to Al of between 0.1 and 1.0, preferably between 0.15 and0.75, most preferably between 0.25 and 0.5. Aluminas also containingalkali metals, possibly in addition to other metals and counter ions,are referred to herein as “alkali-promoted” aluminas. Alkali-promotedalumina, not containing divalent metals, are well suitable in thepresent process. A specific and preferred example of a suitableadsorbent is K-promoted alumina The K-promoted alumina preferablycomprises 5-25 wt % K, more preferably 10-15 wt % K, based on totalweight of the adsorbent.

When the adsorbent further comprises magnesium oxide (magnesia), itpreferably has an atomic Mg to Al+Mg ratio of between 0.05 and 0.85,more preferably between 0.1 and 0.8, most preferably between 0.2 and0.5. Aluminas that further comprise magnesia are referred to as“hydrotalcites”. Where reference is made to alumina, magnesia and thelike, these include the oxides, but also hydroxides and otherequivalents of the oxides of aluminum, magnesium, respectively. Herein,sulphides and hydrosulphides are considered equivalent with oxides andhydroxides respectively. It is envisioned that upon adsorption ofsulphur species such as H₂S metal oxides and hydroxides present in theadsorbent are converted into sulphides and hydrosulphides. When present,metal sulphides and hydrosulphides are likely to be transformed to metaloxides and hydroxides. It is however preferred that at least metaloxides are present in the adsorbent. Magnesium is particularly preferredover e.g. zinc, for feed gas mixture containing high amounts ofsulphur-containing species such as H₂S, since the magnesium-basedadsorbents were found to be chemically relatively insensitive to thesulphur compounds, i.e. not be deteriorated in use.

Aluminas also containing magnesium and/or other divalent metals, andalso containing alkali metals, possibly with other metals and counterions, are referred to herein as “alkali-promoted hydrotalcites”. Thealuminas may be used in a manner known per se, which may compriseadmixing metals oxides and further additives with the alumina orhydrotalcite or other base material in a dry state or in a solution or aslurry, and optionally drying and calcining the resulting mixture. Thealumina may be any form of alumina which can be rehydrated, inparticular which has a level of hydroxyl groups. Examples includegamma-alumina, boehmite, gibbsite, bayerite.

The adsorbent to be used in the process according to the first aspect ofthe invention can be represented by the following chemical formula:

[M^(II) _((1 x))Al_((αx))M^(III)_(((1 α)x))(OH)_(y)][Z^(n−)]_(((x−y+2)/n))·pH₂O·qM^(I)(A^(m−))_(1/m),

wherein:

-   M^(I) is one or more metals selected from Li, Na, K, Rb and Cs,    preferably from Na and K;-   M^(II) is one or more metals selected from Mg, Ca, Sr, Ba, Co, Ni,    Cu, Zn, Cd and Pb, preferably from Mg, Ca, Ni, Cu and Zn;-   M^(III) is one or more metals selected from Fe, Mn, Cr, Ti and Zr;-   Z^(n−) is one or more anions selected from halide, nitrate or    acetate (n=1), or oxide, sulphate, oxalate or carbonate (n=2);-   A^(m−) is one or more anions selected from hydroxide (m=1) and the    anions as defined for Z above, with m corresponding to n;-   m and n=1 or 2, according to A and Z, respectively;-   x=0.05-1, preferably 0.1-1.0, more preferably 0.2-0.95, most    preferably 0.4-0.8;-   α=0-1, preferably 0.5-1, most preferably α=0.95-1;-   p=0-15;-   q=0.1-1; and-   y=0-4.

Specific examples of hydrotalcites of the above formula are referred toherein as KMG30 having an MgO:Al₂O₃ weight ratio of 30:70 and having theformula [Mg_(0.35)Al_(0.65)(OH)₂][CO₃ ²⁻]_(0.325).0.5H₂O.0.32K(CO₃²⁻)_(0.5) with a molar ratio K:Mg:Al of about 1.0:1.1:2.0 and a molarratio of K:(Mg+Al) in the order of 1:3.1 (0.32:1); and as KMG70 havingan MgO:Al₂O₃ weight ratio of 70:30 and having the formula[Mg_(0.74)Al_(0.26) (OH)₂][CO₃ ²⁻]_(0.13).0.5H₂O.0.27K(CO₃ ²⁻)_(0.5)with a molar ratio K:Mg:Al of about 1.0:2.7:0.9 and a molar ratio ofK:(Mg+Al) in the order of 1:3.6 (0.27:1)

The anions in the complex metal oxides are as defined above. Preferablythe adsorbent comprises hydroxide and/or carbonate anions in order toensure sufficient alkalinity for an effective adsorption of acidic gasspecies. In particular, at least 50% of the anions (expressed inmonovalent equivalents) consist of hydroxide and/or carbonate.

Suitable inorganic oxides can have a layered structure, wherein part ofthe anions is arranged in layers interposed between layers containingthe cations. Examples of suitable layered oxides include thehydrotalcites having proportional formula's such asMg₆Al₂(CO₃)(OH)₁₆.4(H₂O) or similar combinations with different Mg:Alratios. Other suitable oxides include analogues wherein magnesium isabsent (e.g. scarbroite) or is replaced by calcium (e.g.alumohydrocalcites), strontium (e.g. montroyalite) or barium (e.g.dreserrites), as well as Mg/Fe, Mg/Cr, Mg/Mn, Ni/Al, etc. analogues(pyroaurite, stichtite, desautelsite, takovite).

In a preferred embodiment, the adsorbent as prepared for step (a) of theprocess of the invention has a H₂O content of at most 5 wt %, based onthe total weight of the adsorbent. In order to obtain such H₂O contents,it may be beneficial to dry the adsorbent prior to step (a). Methods andmeans for drying the adsorbent are known in the art and describedfurther below in the context of the regeneration of step (c).

The adsorbent may have been thermally treated, i.e. it may have beenheated at a temperature above about 200° C., even more especially aboveabout 400° C. For instance, assuming a hydrotalcite adsorbent, whenheating this hydrotalcite in the reactor before or during anadsorption-desorption reaction, the hydrotalcite modifies to a promotedalumina, such as K₂CO₃ and MgO promoted alumina, since at elevatedtemperatures, the hydrotalcites may at least partially rearrange inmixed oxides while losing hydrotalcite crystalline structure and layereddouble hydroxide structure. This is well known in the art and is forinstance described in U.S. Pat. No. 5,358,701, U.S. Pat. No. 6,322,612and WO 2005/102916.

During step (a) of the process according to the first aspect of theinvention, the feed gas is contacted with the adsorbent at a temperatureof 250-500° C., preferably of 280-450° C., more preferably 300-420° C.Step (a) is preferably performed at a pressure of below 15 bar, such as1-15 bar, more preferably 1-10 bar, for a period of at least 5 minutes,such as 10 minutes—e.g. 12 h, preferably 30 minutes—8 h. The flow rateof the feed gas in step (a) may be e.g. 1-25 m³ per kg of sorbent per h,preferably 4-20 m³/kg/h. During the contacting, certain species, inparticular acidic species, are adsorbed onto the adsorbent, while otherspecies may pass through the adsorbent material without being adsorbed(“slip through”). Such non-adsorbed species typically included inertgases such as nitrogen, argon and hydrocarbons. Together, thenon-adsorbed species form a first product gas, which is depleted inacidic species, particularly in H₂S equivalents, compared to the feedgas. The first product gas is thus the off-gas of step (a). Step (a) ispreferably continued until breakthrough of H₂S equivalents commences,which end up as a mixture of H₂S and COS in the first product gas asexplained above. It should be noted that the conditions during step (a)are typically such that no water gas shift reaction occurs.

The inventors surprisingly found that when the water content of the feedgas is sufficiently low, the adsorbent material according to theinvention has an increased selectivity for H₂S (and/or equivalentsthereof), when compared to adsorption by the same adsorbent with a “wet”feed gas, i.e. having a H₂O to H₂S equivalents molar ratio of above(5+X). With such a wet feed gas, the adsorbent adsorbs relatively largeamounts of CO₂ while adsorbing comparatively low amounts of H₂S, e.g. asdescribed in WO 2013/019116. Although the concentration of CO₂ of thefeed gas is typically several factors higher than the concentration ofH₂S equivalents in the feed stream, the molar ratio of H₂S (and/orequivalents thereof) to CO₂ that is adsorbed onto the adsorbent issurprisingly high, even above 1, when a dry feed gas is used. In thisrespect, it is irrelevant whether the equivalents of H₂S, typically COSand/or CS₂, are converted to H₂S when being in the gaseous state andsubsequently adsorbed as H₂S, or that the equivalents of H₂S are firstadsorbed as such and subsequently converted to H₂S. The sulphur speciesthat is desorbed during step (b) is at all times H₂S, and the secondproduct gas is substantially free of equivalents of H₂S such as COS andCS₂. Without being bound to a theory, it is believed that the adsorbentacts as catalyst for the conversion of the equivalents of H₂S to H₂S,and that the conversion occurs when an equivalent of H₂S is in adsorbedstate. In the context of the present invention, reference is made toadsorption of H₂S equivalents.

The inventors found that increasing amounts of water in the feed gasdecreases the selectivity for H₂S equivalents. As the amount of H₂Sequivalents being adsorbed during step (a) decreases, the H₂S content inthe second product gas, i.e. the off-gas of step (b), decreases. The H₂Scontent in the second product gas becomes unacceptably low when theratio of H₂O to H₂S equivalents in the feed gas is above (5+X). Thedrier the feed gas the higher the capacity of the adsorbent for H₂Sequivalents, thus it is preferred that the H₂O to H₂S equivalents ratioin the feed gas is 0 or close to 0. When the H₂O to H₂S equivalentsratio is in the range of 0-(5+X), preferably 0-(2+X), more preferably0-(1+X), the sorbent capacity for CO₂ and H₂S equivalents is more orless similar, i.e. CO₂ to H₂S adsorption is 2:1-1:2, in step (a) of theprocess according to the first aspect of the invention. For completelydry feed gases, i.e. having a H₂O to H₂S equivalents ratio of 0 or closeto 0, the ratio of CO₂ to H₂S being adsorbed in step (a) was as high as1.5, which slightly decreased to 0.6 for a feed gas comprising H₂O andH₂S equivalents in a ratio of about 2. Such capacities for H₂Sequivalents afford excellent second product gases in terms of H₂Scontent and H₂S to CO₂ ratios. H₂S capacities of the adsorbent werefound acceptable for feed gases comprising water up to a H₂O to H₂Sratio of (5+X).

In view of the adsorption of H₂S equivalents during step (a), the firstproduct gas, i.e. the gas issuing from step (a), is depleted in H₂S; ittypically contains substantially no H₂S, i.e. less than 10 ppm,advantageously less than 5 ppm or even less than 1 ppm. The firstproduct gas generally contains less than 0.1 times, preferably 0.05times, most preferably less than 0.02 times the level of H₂S equivalentsof the feed gas, and the level may be as low as 0.001 or even 0.0002times the feed level. Alternatively, or additionally, the first productgas has a molar ratio H₂S equivalents to CO₂ of less than 0.005,preferably less than 0.002, down to e.g. 0.0001 or even 0.00001. Whencompared to the feed gas, the first product gas has an decreased ratioof H₂S equivalents to CO₂.

The first product gas may be emitted into the environment, which isacceptable in view of its negligible sulphur content, althoughincineration of the first product gas prior to emission may be desiredin case it contains hydrocarbons, CO and/or H₂. In view of its lowsulphur content and potentially high CO₂ content, depending on the CO₂content of the incoming feed gas, the first product gas may also besuitable for carbon capture and storage (CCS). Alternatively, it may beused or further processed in any way conceivable, e.g. as a high-CO₂source gas, fuel gas or syngas.

The contacting of step (a) may be performed by any means known in theart for contacting a gaseous stream with a solid material. Typically, apacked bed reactor is used, e.g. in the form of a column or tube whereina tubular reactor is packed with the adsorbent material, although afluidised bed may also be used. The stream of the feed gas is led overor through said reactor. In case a column is used, the feed gas isconveniently injected into the adsorbent, e.g. at the bottom or top ofthe column, and the first product gas is released, conveniently at theother side of the column. Alternative arrangements, including horizontalflows or flow entering and leaving the column at the long sides, arealso well suitable. After contacting step (a), the adsorbent has beenbecome loaded with acidic species, in particular H₂S and CO₂.

In step (b), the adsorbed molecules are desorbed from the adsorbent, bypurging (rinsing) with a purging gas. The purging gas used in step (b)comprises steam, preferably the purging gas is steam, although minoramounts of other components such as N₂, Ar, H₂S or CO₂ may also bepresent in the purging gas. It is preferred that the content of othergases than steam and optionally inert gases is kept low. Preferably atleast 75% of the purging gas is steam and optionally inert gas(es), morepreferably at least 90%, most preferably at least 95% is steam andoptionally inert gas(es). Typically, the ratio of steam to inert gas isin the range of 5/95-100/0, more preferably 20/80-100/0, even morepreferably 50/50-100/0, most preferably 90/10-100/0. The CO₂ content iskept low, preferably below 0.1% (1000 ppm), especially below 100 ppm oreven below 10 ppm. The presence of CO₂ is not required for effectivedesorption and only leads to a reduced H₂S content in the firsteffluent, compared to the CO₂ content (i.e. decreasing the H₂S/CO₂ molarratio). It is also preferred to keep the H₂S content low in the purginggas, preferably 0-1%.

In one embodiment, the purging gas comprises a reducing agent. The typeand content of the reducing agent comprised in the purging gas istypically the same as defined above for the feed gas. The presence of areducing agent in the purging gas ensures that any adsorbed SO_(x)species is reduced to H₂S upon desorption. It is preferred that the feedgas comprises a reducing agent as defined above, and the purging gas issubstantially free of reducing agent (i.e. comprises <1% reducing agent,especially below 100 ppm or even below 10 ppm). In an especiallypreferred embodiment, the purging gas is substantially pure steam, i.e.comprising at least 95% steam or even at least 99% steam or about 100%steam. Any further component, apart from steam, that is present in thepurging gas reduces the H₂S and CO₂ content of the second product gas,based on dry weight. The potentially large amounts of water that arepresent in the second product gas are readily reduced by e.g.condensation. In an alternative embodiment, the purging gas is a Claustail gas that has not been subjected to drying. The H₂O present in theClaus tail gas enables desorption of H₂S, thus giving rise to a Claustail gas enriched in H₂S as second product gas.

The temperature at which step (b) is performed preferably ranges from250-500° C., more preferably 300-450° C. Step (b) is preferablyperformed at a pressure of below 15 bar, such as 1-15 bar, morepreferably 1-10 bar, for a period of between 10 minutes and e.g. 48 h,preferably between 20 minutes and 24 h. The flow rate of the purge gasin step (b) may be similar to the flow rate of step (a), e.g. 1 to 25 m³per kg of sorbent per h, preferably 4-20 m³/kg/h. Although thetemperatures and pressures employed in steps (a) and (b) may vary, theprocess is advantageously performed with steps (a) and (b) at about thesame temperature and pressure. Thus, any difference in temperaturebetween step (a) and step (b) is preferably less than 50° C., morepreferably less than 20° C., and any difference in pressure between step(a) and step (b) is preferably less than 50%, more preferably less than25%, or less than 1 bar. In other words, no pressure swing (i.e. a cyclecomprising relatively high-pressure adsorption and relativelylow-pressure desorption) or temperature swing (i.e. a cycle comprisingrelatively low-temperature adsorption and relatively high-temperaturedesorption) is required to obtain H₂S enrichment according to thepresent invention. Step (b) may be performed in co-current mode orcounter-current mode with respect to adsorption step (a). For optimiseddesorption, it is preferred that step (b) is performed incounter-current mode with respect to step (a).

In a preferred embodiment, the process according to the first aspect ofthe invention runs in parallel, i.e. at least two reactor bedscomprising the adsorbent according to the invention, preferably inseparate reactors, are used simultaneously, one is performing step (a),i.e. is being fed with the feed gas and expels the first product gas,and the other one is performing step (b), i.e. is being fed with thepurge gas and expels the second product gas. Preferably, the bedoperating in step (b) subsequently performs step (c), as describedbelow, before the beds are switched and the now loaded bed is subjectedto step (b) and the now purged and preferably dried bed is subjected tostep (a). Alternatively, a third bed may be used, which is subjected tostep (c) while a first bed is being subjected to step (a) and a secondbed is being subjected to step (b). In this embodiment, the two, threeor more beds operate according to the cyclic scheme of step (a)→step(b)→step (c)→step (a)→etc.

During purging with a purging gas comprising steam, water moleculesoccupy adsorption sites on the adsorbent, thereby releasing the acidicspecies such as H₂S, CO₂ that were adsorbed during step (a). Thesedesorbed species, together with a large part of purging gas that is notadsorbed, make up a second product gas stream (effluent). The secondproduct gas is a main product of the process according to the firstaspect of the invention, and is enriched in H₂S compared to the feedgas. Here, “enrichment” refers to the increased content of H₂S (based ondry weight) compared to the content of H₂S equivalents in the feed gas(based on dry weight) and/or to the increased molar ratio of H₂S (and/orequivalents thereof) to CO₂ compared to the feed gas. It should be notedthat the second product gas is substantially free of equivalents of H₂S,since all sulphur species that are adsorbed during step (a) are desorbedas H₂S during step (b). When compared to the feed gas, the secondproduct gas has an increased ratio of H₂S equivalents to CO₂. The molarratio of H₂S to CO₂ in the second product gas is typically increased tobetween about 1 and about 2, whereas the H₂S equivalents to CO₂ molarratio in the feed gas may be as low as 0.001 or even lower. As such, anenrichment up to three orders of magnitude may be achieved, which isunprecedented in the art.

The second product gas typically contains H₂S, CO₂ and H₂O. It mayfurther contain nitrogen as well as low levels of noble gases, carbonmonoxide, hydrocarbons, depending on the composition of the purge gas,while it is preferred that the combined level of such furthercomponents, other than H₂S, CO₂ and H₂O, is less than 10%, morepreferably less than 5%. Preferably, the H₂S content of the secondproduct gas is 5-75%, more preferably 10-70%, most preferably 20-60%,based on dry weight of the gas. Likewise, the CO₂ content of the secondproduct gas is preferably below 70%, more preferably below 50%, evenmore preferably below 40%, based on dry weight of the gas. Mostpreferably, the CO₂ content is below 30%. Although an as low as possibleCO₂ content is preferred, some CO₂ will typically end up in the secondproduct gas, in view of adsorption thereof in step (a) and subsequentdesorption in step (b). Thus, the typical CO₂ levels of the secondproduct gas are 2-40%, or 5-35%, or even 10-30%, based on dry weight ofthe gas. It is especially preferred that the H₂S content issubstantially equal or higher than the CO₂ content. The second productgas of the process of the invention has a molar ratio H₂S equivalents toCO₂ of at least 0.25, preferably at least 0.5, up to e.g. 10, mostpreferably in the range of 0.75-2.

It is further preferred that the combined level of H₂S and CO₂ isbetween 10 and 95%, more preferably between 20 and 80%, based on dryweight of the gas. Since COS and CS₂ were found to readily adsorb anddesorb under the conversion to H₂S and not to revert to COS or CS₂ upondesorption, no or only a negligible amount of COS and CS₂ is observed inthe second product gas. Also hardly any or even an untraceable amount ofSO_(x) is observed in the second product gas, in view of the presence ofa reducing agent, even if the reducing agent is present in the feed gas.Thus, H₂S is the sole sulphur species which is desorbed. The level ofany other sulphur species, including COS, CS₂, SO₂, in the secondproduct gas is below 20 ppm, especially below 10 ppm, in particular, thecombined levels of all such species is below 20 ppm, in particular lessthan 10 ppm.

The second product gas, in view of its high H₂S content, is ideallysuited to be subjected to further application in e.g. Claus sulphurproduction. Since Claus tail, appropriately after pre-drying asdescribed further below, gases are especially suitable as feed gas forthe process according to the first aspect of the invention, and thesecond product gas may be recycled to the feed in a Claus process, thepresent process is particularly suited to be incorporated with a Clausplant. These aspects of the invention are discussed further below.Another advantageous application is the desulphurization of fuel gas ine.g. refineries. The low hydrocarbon content of the second product gaseffluent is particularly advantageous, as hydrocarbons are undesirablein the downstream Claus process.

If desired, a flushing (rinsing) step may be inserted between loadingstep (a) and desorption step (b), so as to avoid mutual contamination ofproduct gases issuing from steps (a) and (b). Such rinsing may beperformed using the same temperatures, pressures and flow rates of steps(a) and (b), and may be continued for e.g. between 1 and 15 minutes.Suitable rinsing gases include inert gases, such as nitrogen, and mayalso contain carbon dioxide, hydrogen or methane, while levels of H₂Oshould preferably be low (preferably as defined for the feed gas inabsolute terms, i.e. below 5%, more preferably below 2%, most preferablybelow 0.5%) and sulphur compounds should essentially be absent (lessthan 10 ppm).

After the purging step (b), the adsorbent is typically regenerated so asto allow its reuse in step (a) in the process of the invention. Thisregeneration includes removal (desorption) of H₂O from the adsorbent, tosuch an extent that, depending on the water content of the feed gas, theH₂O to H₂S levels during adsorption step (a) are set to the toappropriate conditions as described above. Thus, according to anespecially preferred embodiment, the process according to the firstaspect of the invention further comprises a step (c) wherein the purgedadsorbent is regenerated by drying (i.e. removal of H₂O). The drying ofstep (c) may be accomplished by any means known in the art for drying asolid adsorbent material. Suitable means include reducing the pressurein the reactor (e.g. pressure swing adsorption (PSA) or vacuum pressureswing adsorption (VPSA) mode), increasing the temperature (e.g.temperature swing adsorption (TSA) mode), contacting the purgedadsorbent with dry gas (e.g. passing a gas through the reactor). The drygas should contain less than 0.1% water, and may comprise nitrogen,noble gases, carbon dioxide, and possibly low levels carbon monoxide andhydrocarbons. Combinations of drying techniques, e.g. depressurisationand heating, may also be used.

The process of the invention is preferably performed in multiple cyclesof steps (a)-(c). In other words, the process is performed in cycles ofsteps (a) to (c). The present process is preferably carried out incyclic mode. Since contamination of the adsorbent does hardly occur, alarge number of cycles, e.g. several thousands or even more, may beperformed before any cleaning or exchange of adsorbent or othermaintenance steps are needed.

The invention also pertains to the use of an H₂S-enriched gas asobtained in step (b) of the process of the invention as an H₂S feed gasfor processes in which appreciable levels, e.g. at least 10% or even atleast 25% of H₂S are required. Examples of such process include theproduction of elemental sulphur, e.g. in the Claus process or inbiological partial oxidation (Thiopaq), or for the production ofsulphuric acid or other sulphur compounds.

Claus Process

According to a second aspect, the invention concerns a Claus process asknown in the art, wherein the process according to the first aspect ofthe invention is implemented. Claus processes are known in the art andused for desulphurisation of gases, wherein H₂S is converted toelemental sulphur via the overall chemical reaction:

2 H₂S+O₂→2 S+2 H₂O   (3)

This overall reaction may be a combination of several subreactions,which typically occur in several stages of the Claus process. A typicalClaus process includes a thermal stage wherein the feed gas comprisingH₂S is heated to a temperature above 800° C. by reaction of asub-stoichiometric amount of oxygen, wherein combustion of H₂S via SO₂to S, and a catalytic stage, wherein H₂S reacts with SO₂ in the presenceof an alumina or titania based catalyst. Side reactions that typicallyoccur during the Claus process include the formation of H₂S, COS, CS₂and SO₂. These species, together with unreacted H₂S make up the Claustail gas, which is the major by-product of elemental sulphur produced inthe Claus plant. Furthermore, the Claus process can be tuned as known inthe art such that SO₂ is typically absent in the Claus tail gas.

Typical Claus feeds include sour natural gas, or more typically theH₂S-enriched stream obtained by amine scrubbing thereof, and gaseousby-products of refineries or other industries. Such gaseous by-productsare typically obtained by desulphurization steps, wherein H₂Scontaminants are removed from the main product stream, e.g. by aminescrubbers. As such gaseous steams are obtained or formed in largequantities, the Claus process is ubiquitous in present-day industry. Tobe suitable for conversion by Claus, the feed gas requires a minimum H₂Scontent of 15%, but at least 25% H₂S is preferred, which renders manyH₂S containing gaseous stream unsuitable to be directly used as Clausfeed gas. The gases that are suitable as feed gas for the processaccording to the first aspect of the invention are typical examples ofgases that have a too low H₂S content to be suitable as Claus feed gas.However, the second product gas obtained by the process according to thefirst aspect of the invention contains H₂S in a sufficiently highcontent to be suitable as feed gas for the Claus process. The processaccording to the first aspect of the invention can thus be used toenrich a gaseous stream in H₂S in order to make it suitable as feed gasfor a Claus process.

The process according to the second aspect of the invention concerns aprocess for converting H₂S to elemental sulphur (S) comprising the stepof subjecting the second product gas as obtained in the processaccording to the first aspect of the invention, optionally afterpre-drying, to a Claus process to obtain elemental sulphur and a tailgas comprising H₂S equivalents and CO₂. If needed, the second productgas is pre-dried, i.e. the H₂O content is reduced, in order to renderthe second product gas suitable to be subjected to a Claus process. Therequired composition of the second product gas to be suitable as feedgas for a Claus process depends on whether or not the second product gasis combined with a further feed gas, typically an H₂S-enriched streamobtained by amine scrubbing of sour natural gas or an H₂S-containinggaseous by-product of a refinery or other industry, before or upon beingsubjected to the Claus process, and to the composition of said furtherfeed gas. The skilled person knows to what extent the second product gasneeds to be dried in order to be suitable to be used as feed gas for theClaus process according to the second aspect of the invention. Any meansof drying as known in the art may be used as pre-drying, such as coolingand/or pressurisation resulting in condensation of water or by otherconventional methods such as absorption or adsorption. Suitable dryingmeans include condensation of steam to liquid water, while keeping H₂Sand other species such as CO₂ and inert gases gaseous. The remaininggaseous components are then fed to the Claus process. Cooling of thesecond product gas from a temperature of about 350° C. to about 40° C.reduces the steam content to about 7%, which is acceptable for a Clausfeed gas. In a preferred embodiment, the second product gas is combinedwith a further feed gas, typically an H₂S-enriched stream obtained byamine scrubbing of sour natural gas or a H₂S-containing gaseousby-product of a refinery or other industry, before or upon beingsubjected to the Claus process.

In a preferred embodiment, the tail gas of the Claus process accordingto the second aspect of the invention, comprising H₂S equivalents andCO₂, is used as feed gas in step (a) of the process according to thefirst aspect of the invention, optionally after pre-drying. In oneembodiment, the Claus tail gas is pre-treated prior to being subjectedto step (a) of the process according to the first aspect of theinvention. Pre-treatment may be employed to lower the H₂O content and/orthe SO₂ content (or the SO_(x) content). As the required H₂O content ofthe feed gas of the process according to the first aspect of theinvention is critical, and typical Claus tail gases are too wet, it ispreferred that the Claus tail gas is pre-dried, before being subjectedas feed gas to the process according to the first aspect of theinvention. Any means of drying as known in the art may be used aspre-drying, such as cooling and/or pressurisation resulting incondensation of water or by other conventional methods such asabsorption or adsorption. Suitable drying means include condensation ofsteam to liquid water, while keeping H₂S equivalents and CO₂ gaseous.The remaining gaseous components are then fed to the process accordingto the first aspect of the invention. Since drier feed gases give riseto increased H₂S adsorption capacity of the adsorbent, it is preferredthat pre-treatment to lower the H₂O content includes a measure to lowerthe H₂O level to well below 1%. Such a measure may include a glycolrinse of the Claus tail gas and/or contacting the Claus tail gas withmolecular sieves, optionally after one or more of the above-mentionedtechniques. Alternatively or additionally, the H₂O content may belowered by selective permeation of water through a membrane (e.g. byvacuum permeation). Claus tail gases pre-treated as such are especiallysuitable to be used as feed gas for the process according to the firstaspect of the invention, in view of their extremely low or evennegligible water content. Pre-treatment to lower the SO₂ or SO_(x)content is particularly preferred, since the presence of SO₂ isundesirable in the feed gas of the process according to the first aspectof the invention, as discussed above, and typically involves subjectinga SO_(x)-containing gas to a hydrogenation-hydrolysis step, as known tothe art, to convert SO_(x) to H₂S. The H₂ required in this respect mayoriginate from the Claus tail gas itself or from substoichiometriccombustion of fuel (e.g. natural gas) to a mixture of CO and H₂. SO_(x)can also be lowered by scrubbing with an alkaline solution followed bychemical reduction, e.g. using hydrogen, or by biological reduction,e.g. using bacteria of the genera Desulfovibrio, Desulfobacterium,Desulforomonas or the like. Alternatively and preferably, the Clausprocess is tuned as known in the art such that the tail gas issubstantially free of SO_(x) (i.e. content below 100 ppm, preferablybelow 10 ppm). Such tuning is typically accomplished by tuning theamount of O₂ added to the Claus feed in the thermal stage, in order tolimit the amount SO₂ produced so that the off-gas of the Claus plantdoes not contain SO₂, but only H₂S (and optionally COS and/or CS₂).

System

In a third aspect, the invention concerns a system designed to implementthe processes according to the first and second aspects of theinvention, comprising (A) a Claus unit and (B) an adsorption moduleequipped with (b1) a bed of adsorbent comprising alumina and one or morealkali metals. Any type of Claus unit or even an entire Claus plant asknown in the art may be employed as Claus unit (A) in the systemaccording to the invention. Suitable Claus units typically include athermal unit and a series of catalytic reactors with intermediatecooling units. In the thermal unit, the Claus feed is mixed with asubstoichiometric amount of air (or oxygen) and subsequently burnt.Herein, any hydrocarbon present in the Claus feed is preferablycombusted and part of the H₂S is converted into SO₂, during which someelemental sulphur is produced. The reaction mixture is transferred to aseries of catalytic reactors with intermediate cooling and elementalsulphur condensation stages. Typically, at least two, preferably threeor even four catalytic reactors are employed. Each catalytic reactor isemployed with a catalyst bed, typically an activated alumina. Herein,the conversion of 2 H₂S and SO₂ into S and 2 H₂O is catalyzed. Sincethis reaction is an equilibrium reaction, multiple catalytic stages arepreferred in order to obtain high yields of elemental sulphur. Remaininghydrocarbons that may still be present in this step may deactivate thecatalyst. A standard Claus plant contains three catalytic reactors,which enables sulphur recoveries of 95-98 wt %. Claus unit (A) comprisesa first inlet (a1) for receiving a gaseous feed stream and preferably asecond inlet (a2) for receiving a further gaseous feed stream. The firstinlet (a1) is intended for receiving the second product gas of theprocess according to the first aspect of the invention, while theoptional second inlet (a2) is for receiving an optional further feedgas, as discussed above. Alternatively and preferably, the systemaccording to the invention comprises means (a3) for combing the secondproduct gas and a further feed gas to obtained a combined feed gas priorto the introduction of the combined feed gas into the Claus unit. Inthis embodiment, first inlet (a1) is intended for receiving the combinedgas feed comprising the second product gas of the process according tothe first aspect of the invention and the further feed gas. Any meansfor combining as known in the art can be used as means (a3), such as “inline” or “in pipe” mixing. Typically, the Claus unit comprises a thirdinlet (a4) for receiving air. The Claus unit further comprises a firstoutlet (a5) for discharging elemental sulphur (S) and a second outlet(a6) for discharging a tail gas. The Claus unit may comprise furtheroutlets for discharging elemental sulphur and/or tail gas.

The adsorption module (B) comprises at least one bed reactor, whereinthe bed (b1) comprises, preferably consists of, the adsorbent accordingto the invention as bed material. The adsorbent according to theinvention comprises alumina and one or more alkali metals and is furtherdescribed above for the process according to the first aspect of theinvention. Adsorption module (B) further comprises a first inlet (b2)for receiving the feed gas and optionally the purging gas, although itis preferred that the purging gas is received via a second inlet (b3),and a first outlet (b4) for discharging the second product gas andoptionally the first product gas, although it is preferred that thefirst product gas is discharged via a second outlet (b5). A single bedreactor may be used, the bed (b1) of which is alternately loaded in step(a), i.e. H₂S equivalents adsorb, and unloaded in step (b), i.e. H₂Sdesorbs, or two or more reactors in parallel may be used in module (B).Preferably, adsorption module (B) comprises two or more bed reactors,which enables performing step (a) of the process according to the firstaspect of the invention in a first reactor and simultaneously step (b)of the process according to the first aspect of the invention in asecond reactor. As such, a continuous process is possible, wherein afeed gas may continuously be fed to adsorption module (B), alternatingto the first and second reactor, and a purge gas may continuously be fedto adsorption module (B), alternating to the second and first reactor.The reactor to which the feed gas is fed discharges the first productgas, while the reactor to which the purge gas is fed discharges thesecond product gas. Even more preferred is the use of three bedreactors, wherein a first bed is being subjected to step (a) while asecond bed is being subjected to step (b) and a third bed to step (c).In this embodiment, the two, three or more beds operate according to thecyclic scheme of step (a)→step (b)→step (c)→step (a)→etc.

The bed reactor is preferably a packed bed reactor or a fluidized bedreactor, more preferably a packed bed reactor. The reactor is typicallyin the form of a column, tube or vessel, wherein preferably a reactor ispacked with the adsorbent material. The reactor is designed as known inthe art, typically to enable the stream of the feed gas or the purgegas, which is introduced via one of the inlets (b2) or (b3), to be ledover or through the bed, towards one of the outlets (b4) or (b5). Incase a column is used, the inlet (b1) for receiving the feed gas isconveniently placed at the bottom or top of the column, and the outlet(b4) for discharging the product gases is conveniently placed at theother side of the column. Alternative arrangements, including horizontalflows or flow entering and leaving the column at the long sides, arealso well suitable.

In the system according to the invention, the Claus unit (A) and theadsorption module (B) are interconnected, i.e. the outlet of one is influid connectivity with the inlet of the other, preferably by means of aconduit. As such, the constant flow of (liquid) streams through thesystem is enabled. Thus, the second outlet (a6) of the Claus unit (A) isin fluid connection with the inlet (b2) of the adsorption module (B),and the first outlet (b4) of the adsorption module (B) is in fluidconnection with the first inlet (a1) of the Claus unit (A). Using sucharrangement, the Claus tail gas is effectively recycled to the Clausunit by increasing the H₂S content thereof. In view of legalrequirements, Claus tail gases need to be treated to remove H₂Sequivalents before it may be expelled into the environment afterincineration. A major advantage of the recycle according to the presentinvention is that conventional tail gas treatments (TGT) are no longerrequired, which are typically less environmentally friendly and moreexpensive than the process according to the first aspect of theinvention. For example, amine scrubbing as TGT removes H₂S together withsignificant quantities of CO₂, giving a typical ratio of H₂S to CO₂ ofbelow 0.1, which renders this gas less suitable to be recycled to theClaus process. The processes according to the invention areadvantageous, since a high quality recycle gases for the Claus unit areobtained. For typical Claus tail-gases having a high CO₂/H₂S ratio,conventional separation technologies are not capable to provide highlyenriched H₂S streams. Moreover, conventional TGT usually create aseparate sulphur-product such as sulphuric acid. Separation byadsorption gives potentially smaller TGT units compared to conventionalTGT units.

In a preferred embodiment, the Claus tail gas as discharged from theClaus unit (A) via outlet (a6) is first led to a steam removal unit (C1)before being received by adsorption module (B) via inlet (b2). Steamremoval unit (C1) is thus integrated in the fluid connectivity betweenoutlet (a6) and inlet (b2). Unit (C1) comprises means for removing steamfrom the Claus tail gas. Any type of such means as known in the art maybe used, such as means for cooling and/or pressurisation resulting incondensation of water or other conventional means such as absorption oradsorption means. More preferably, the steam removal means includes ameasure to lower the H₂O level to well below 1%. Such a measure mayinclude a glycol rinse of Claus tail feed gas and/or contacting theClaus tail gas with molecular sieves, optionally after one or more ofthe above-mentioned techniques. Alternatively or additionally, the H₂Ocontent may be lowered by selective permeation of water through amembrane (e.g. by vacuum permeation). Unit (C1) is designed forreceiving the Claus tail gas originating from outlet (a6) of Claus unit(A) to the means for steam removal and for discharging the Claus tailgas which is depleted in steam from the means for steam removal. TheClaus tail gas depleted in steam is then led to inlet (b2) of adsorptionmodule (B). It is likewise preferred that a similar steam removal unit(C2) is integrated in the fluid connectivity between outlet (b4) andinlet (a1) or, if present, means (a3). Unit (C2) comprises means forremoving steam from the second product gas. Any type of such means asknown in the art may be used, such as means for cooling and/orpressurisation resulting in condensation of water or other conventionalmeans such as absorption or adsorption means. Unit (C2) is designed forreceiving the second product gas originating from outlet (b4) ofadsorption module (B) to the means for steam removal and for dischargingthe second product gas which is depleted in steam from the means forsteam removal. The second product gas depleted in steam is then led toinlet (a1) or means (a3) of the Claus unit (A). In the context of thepresent invention, units (C1) and (C2) are used for pre-drying asdescribed for the processes according to the first and second aspects ofthe invention.

In a further preferred embodiment, a SO_(x) removal unit is integratedin the fluid connectivity between outlet (b4) and inlet (a1), preferablydownstream of the unit C2 if present. The presence of such a SO_(x)removal unit is particularly preferred for Claus tail gases containingSO_(x). The SO_(x) removal unit comprises means for removing SO_(x) fromthe Claus tail. Suitable means for removing SO_(x) includehydrogenation-hydrolysis means, which is known to the art to covertSO_(x) to H₂S, means for scrubbing with an alkaline solution followed bychemical reduction, e.g. using hydrogen, or means for biologicalreduction, e.g. using bacteria of the genera Desulfovibrio,Desulfobacterium, Desulforomonas or the like. The SO_(x) removal unit isdesigned for receiving the Claus tail gas originating from outlet (a6)of Claus unit (A), optionally via unit (C1), to the means for SO_(x)removal and for discharging the Claus tail gas which is depleted inSO_(x) from the means for steam removal. The Claus tail gas depleted inSO_(x) is then led to inlet (b2) of adsorption module (B), optionallyvia unit (C1).

DESCRIPTION OF THE FIGURES

A preferred embodiment of the system according to the invention isdepicted in FIG. 1. Claus unit (A) may be any Claus unit or Claus plantas known in the art. It comprises a first inlet (a1) for receiving acombined feed gas originating from means (a3) for combining the secondproduct gas and a further feed gas. Unit (A) further comprises a firstoutlet (a5) for discharging elemental sulphur and a second outlet (a6)for discharging a Claus tail gas. Second outlet (a6) is in fluidconnectivity via steam removal unit (C1) with inlet (b2) of theadsorption module (B). Adsorption module (B) comprises a bed (b1)containing the adsorbent according to the invention as bed material, afirst inlet (b2) for receiving the Claus tail originating from unit (C1)and a second inlet (b3) for receiving a purge gas. Module (B) furthercomprises a first outlet (b4) for discharging the second product gas anda second outlet (b5) for discharging the first product gas. Module (B)is designed as such that incoming gases from inlets (b2) and (b3) areled through or over the bed towards outlets (b4) and (b5). First outlet(b4) is in fluid connectivity via steam removal unit (C2) with means(a3). Means (a3) is designed to combine the second product gasoriginating from unit (C2) and a further feed gas.

FIGS. 2-8 depict compositions of the tail gases obtained in examples1-3.

EXAMPLES Example 1

A feed gas containing 10% CO₂, 10% H₂ and 500 ppm H₂S (balanced with N₂)was subjected to adsorption in a packed bed placed in a cylindricalreactor containing 1 g adsorbent. The feed flow was 150 Nml/min, and thebed operated at a temperature of 400° C. and a pressure of 3 bar(a). Theprocess according to the invention was operated in a cyclic co-currentmode. Cycles consisted of an adsorption stage, a flushing stage, apurging stage and a regeneration stage. The adsorption stage wascontinued until full breakthrough of CO₂ and H₂S was reached.Subsequently, the loaded adsorbent was flushed with 10% Ar in N₂(flow=150 Nml/min) and then purged with a purging gas containing 30% H₂O(balanced with Ar and N₂; flow=150 Nml/min). As last step in the cycle,the adsorbent loaded with H₂O was regenerated by flushing with a dryinert gas (10% Ar in N₂; flow=150 Nml/min). The adsorbents used wereK-promoted hydrotalcite MG30 (KMG30), K-promoted alumina (20 wt % K₂CO₂on alumina) and unpromoted MG30 (control). A similar experiment wasconducted with 0.5 g Na-promoted MG30 as adsorbent, which operated at350° C. and 1 bar(a) and wherein the gas flows (feed, purge and flushes)were 100 Nml/min.

FIGS. 2-5 depict the tail gas (effluent) composition of a cycle of eachof the four experiments: FIG. 2 shows the results for KMG30 asadsorbent, FIG. 3 for K-promoted alumina, FIG. 4 for Na-promoted MG30and FIG. 5 for unpromoted MG30. Ar levels were also determined (data notshown), to visualise the switches between the different stages. Thesestages are indicated with A, D, F1 and F2, wherein “A” denotes theadsorption stage (feed gas), “D” the desorption or purging stage(purging gas), and “F1” and “F2” the first inert flush and second inertflush (regeneration), respectively. On the y-axis, the mass spectrometer(MS) response in arbitrary units is shown.

In all experiments, fast breakthrough of CO₂ was observed after theadsorption period commenced. Because of the high sorbent capacity forH₂S equivalents, breakthrough of H₂S (and COS) was observed at a latertime, indicating saturation of the adsorbent with H₂S and COS at thattime. For the control unpromoted adsorbent, breakthrough times for CO₂,H₂S and COS were similar (FIG. 5), indicating that significantly lessH₂S (and COS) is adsorbed during the adsorption phase. For theexperimental adsorbents, the H₂S+COS slip level before breakthrough asobserved in the first effluent (tail gas of the adsorption phase) wasless than 5 ppm, i.e. >2 orders of magnitude decrease with respect tothe feed gas. It should be noted that no COS was present in the feedgas, meaning that the adsorbent promotes the H₂S+CO₂⇄COS+H₂O equilibriumreaction at the operating conditions. In view of the simultaneousbreakthrough of H₂S and COS, those species are both adsorbed. Upon steamregeneration, CO₂ was released swiftly from the adsorbent, whiledesorption of H₂S is spread over a longer period of time. The secondeffluent (tail gas of the desorption phase) contained H₂S, CO₂, H₂O andinert gases. No desorption of COS was observed, indicating that alladsorbed sulphur species are released as H₂S. For the control unpromotedadsorbent, hardly any H₂S desorption was observed (FIG. 5), reflectingthe small amount of H₂S adsorbed in the adsorption period.

Example 2

Two distinct feed gases containing 10% CO₂, 10% H₂ and 500 ppm or 900ppm H₂S (balanced with N₂) were subjected to adsorption in a packed bedplaced in a cylindrical reactor containing 0.5 g K-promoted hydrotalciteMG30 (KMG30) as adsorbent. The feed flow was 200 Nml/min, and the bedoperated at a temperature of 350° C. and a pressure of 1 bar(a). Theprocess according to the invention was operated in a cyclic co-currentmode. Cycles consisted of an adsorption stage, a flushing stage, apurging stage and a regeneration stage. The adsorption stage wascontinued until full breakthrough of CO₂ and H₂S was reached.Subsequently, the loaded adsorbent was flushed with 10% Ar in N₂(flow=200 Nml/min) and then purged with a purging gas containing 30% H₂O(balanced with Ar and N₂; flow=200 Nml/min). As last step in the cycle,the adsorbent loaded with H₂O was regenerated by flushing with a dryinert gas (10% Ar in N₂; flow=200 Nml/min).

FIG. 6 depicts the tail gas compositions with respect to H₂S and COS forthe adsorption stage of a cycle of each of the two experiments: FIG. 6ashows the results for the feed gas comprising 500 ppm H₂S and FIG. 6bfor the feed gas comprising 900 ppm H₂S. Levels (in ppm) of H₂S, COS and“total S” (i.e. H₂S+COS) are depicted. The start of breakthrough isobserved at about 75 min in FIG. 6a and at about 50 min in FIG. 6b .Before start of breakthrough, the level of total S in the tail gas (sliplevel) was below 5 ppm. Both H₂S and COS were observed at breakthrough,while only H₂S was fed. At about t=130 min (FIG. 6a ) or t=80 min (FIG.6b ), the adsorbent reached full capacity for the H₂S equivalents, andfull breakthrough was reached.

FIG. 7 depicts a more detailed analysis of the tail gas compositionobtained with the feed gas comprising 500 ppm H₂S. Levels (in ppm) ofH₂S, COS and “total S” (i.e. H₂S+COS) are depicted. The results of adifferent cycle as the one presented in FIG. 6a are presented. In thecycle of FIG. 7, the slip level of total S was below 1 ppm (t=840-875min). At full breakthrough, about 500 ppm of sulphur species (H₂S to COSratio of about 1) was observed in the tail gas, at which point theloaded adsorbent was briefly flushed (around t=950) and the purgingstage commenced. During purging, a peak in the H₂S level of the tail gaswas observed, with initial H₂S levels well above 600 ppm, while COS wasabsent in the tail gas from the start of the purging phase. The secondproduct gas obtained during the purging phase thus contained high levelsof H₂S as sole H₂S equivalent.

Example 3

A feed gas containing 10% CO₂, 10% H₂ and 100 ppm CS₂ (balanced with N₂)was subjected to adsorption in a packed bed placed in a cylindricalreactor containing 0.5 g K-promoted hydrotalcite MG30 (KMG30) asadsorbent. The feed flow was 200 Nml/min, and the bed operated at atemperature of 350° C. and a pressure of 1 bar(a). The process accordingto the invention was operated in a cyclic co-current mode. Cyclesconsisted of an adsorption stage, a flushing stage, a purging stage anda regeneration stage. The adsorption stage was continued until fullbreakthrough of CO₂ and H₂S was reached. Subsequently, the loadedadsorbent was flushed with 10% Ar in N₂ (flow=200 Nml/min) and thenpurged with a purging gas containing 30% H₂O (balanced with Ar and N₂;flow=200 Nml/min). As last step in the cycle, the adsorbent loaded withH₂O was regenerated by flushing with a dry inert gas (10% Ar in N₂;flow=200 Nml/min).

FIG. 8 depicts the tail gas composition with respect to H₂S equivalentsfor a cycle of the experiment. Levels (in ppm) of H₂S, COS and “total S”(i.e. H₂S+COS+CS₂) are depicted. In the cycle of FIG. 8, the slip levelof total S was below 1 ppm (t=24770-24830 min). At full breakthrough,about 200 ppm of sulphur species (H₂S to COS ratio of about 7) wasobserved in the tail gas, while no CS₂ was completely absent in the tailgas (H₂S+COS=total S). The loaded adsorbent was briefly flushed (aroundt=24910) and the purging stage commenced. During purging, a peak in theH₂S level of the tail gas was observed, with initial H₂S levels wellabove 250 ppm, while both COS and CS₂ were completely absent in the tailgas from the start of the purging phase. The second product gas obtainedduring the purging phase thus contained high levels of H₂S as sole H₂Sequivalent, while CS₂ was present as sole H₂S equivalent in the feedgas.

Example 4

Seven distinct feed gases containing 10% CO₂, 10% H₂, and varyingamounts of H₂S and H₂O (see Table 2, balanced with N₂) were subjected toadsorption in a packed bed placed in a cylindrical reactor containing0.5 g K-promoted hydrotalcite MG30 (KMG30) as adsorbent. The feed flowwas 200 Nml/min, and the bed operated at a temperature of 350° C. and apressure of 1 bar(a). The process according to the invention wasoperated in a cyclic co-current mode. Cycles consisted of an adsorptionstage, a flushing stage, a purging stage and a regeneration stage. Theadsorption stage was continued until full breakthrough of CO₂ and H₂Swas reached. Subsequently, the loaded adsorbent was flushed with 10% Arin N₂ (flow=200 Nml/min) and then purged with a purging gas containing30% H₂O (balanced with Ar and N₂; flow=200 Nml/min). As last step in thecycle, the adsorbent loaded with H₂O was regenerated by flushing with adry inert gas (10% Ar in N₂; flow=200 Nml/min). During cyclic steadystate, both the breakthrough adsorption capacity at and the totaladsorption capacity of the adsorbent for H₂S equivalents was determined,the results of which are presented in table 2. Breakthrough adsorptioncapacity refers to the capacity of the adsorbent during the adsorptionphase until start of breakthrough, wherein start of breakthrough isdefined as the point in time when the total slip level of sulphurspecies (H₂S+COS) in the tail gas reaches a level of 10 ppm. Totaladsorption capacity refers to the capacity of the adsorbent during theadsorption phase until total breakthrough is reached, i.e. when thecontent of sulphur species (H₂S+COS) in the tail gas is equal to thecontent of sulphur species in the feed gas.

TABLE 2 Feed gas compositions and adsorption capacities for H₂S Feed gascomposition (ppm) Adsorption capacity (mol/kg) Entry H₂S H₂O H₂O/H₂Sbreakthrough total 1 500 0 0 0.57 0.841 2 500 575 1.15 0.40 0.727 3 500900 1.80 0.31 0.617 4 900 0 0 0.62 1.124 5 900 750 0.83 0.50 1.053 6 9002100 2.33 0.33 0.816 7 25000 117000 4.68 n.d. 0.14

For both the feed gases comprising 500 ppm H₂S and the feed gasescomprising 900 ppm H₂S, the adsorption capacity of the adsorbentdecreased with increasing H₂O content of the feed gas. The adsorptioncapacity for H₂S decreased by about a factor 2 when the H₂O/H₂S ratioincreased to above 2. Extrapolating the results in Table 2, theadsorption capacity for H₂S decreased to unacceptable levels in case theH₂O/H₂S ratio increases to above 5, while the best results are obtainedwith a H₂O/H₂S ratio of at most 2. It should be noted that since onlyH₂S was used as H₂S equivalent, X amounts to zero for the feed gasestested here.

1.-18. (canceled)
 19. A process for altering the composition of a gascomprising H₂S equivalents and CO₂, comprising the steps of: (a)contacting a feed gas containing H₂S equivalents, CO₂ and optionallyH₂O, wherein the molar ratio of H₂O to H₂S equivalents is within therange of 0-(5+X), with a solid adsorbent at a temperature of 250-500°C., to obtain a loaded adsorbent and a first product gas; (b) contactingthe loaded adsorbent with a purge gas containing H₂O, to obtain a secondproduct gas; and (c) regenerating the adsorbent after step (b) byremoval of H₂O, wherein the process is performed in cycles of steps (a)to (c), and wherein the feed gas and/or the purge gas contains areducing agent and the adsorbent comprises alumina and one or morealkali metals, and wherein X is defined as:$X = {\sum\frac{n_{i}\lbrack {H_{2}S\mspace{14mu} {equivalent}} \rbrack_{i}}{\lbrack {H_{2}S{\mspace{11mu} \;}{equivalents}} \rbrack}}$wherein [H₂S equivalents] indicates the total concentration of H₂Sequivalents, [H₂S equivalent]_(i) indicates the concentration of aparticular H₂S equivalent i and n_(i) indicates the amount of watermolecules n consumed when said H₂S equivalent i is converted to H₂S. 20.The process according to claim 19, wherein the H₂S equivalents compriseH₂S, COS and/or CS₂.
 21. The process according to claim 19, wherein themolar ratio of H₂S equivalents to CO₂ in the feed gas is below 1,preferably in the range of 0.001-0.1.
 22. The process according to claim19, wherein the molar ratio of H₂S equivalents to CO₂ in the feed gas isin the range of 0.001-0.1.
 23. The process according to claim 19,wherein the feed gas contains 0.1-20% H₂ as the reducing agent.
 24. Theprocess according to claim 19, wherein the adsorbent further comprisesone or more divalent metals, preferably as their oxides, hydroxides,carbonates, sulphides and/or hydrosulphides, preferably the adsorbentfurther comprises MgO.
 25. The process according to claim 19, whereinthe divalent metals are oxides, hydroxides, carbonates, sulphides and/orhydrosulphides.
 26. The process according to claim 19, wherein theadsorbent further comprises MgO.
 27. The process according to claim 23,wherein the alkali metal is K and the adsorbent is K-promoted alumina,or is based on a K-promoted hydrotalcite.
 28. The process according toclaim 19, wherein the process is continued with step (a) after theregeneration of step (c).
 29. The process according to claim 19, whereinstep (b) is performed counter-currently with respect to step (a). 30.The process according to claim 19, wherein the purge gas comprises atleast 75% H₂O.
 31. The process according to claim 19, wherein the firstproduct gas contains less than 10 ppm of H₂S equivalents, and/or thefirst product gas contains less than 0.1 times the level of H₂Sequivalents of the feed gas, and/or the first product gas has a molarratio of H₂S equivalents to CO₂ of less than 0.005.
 32. The processaccording to claim 19, wherein the second product gas has a molar ratioof H₂S equivalents to CO₂ of at least 0.5.
 33. The process according toclaim 19, wherein the feed gas is an optionally pre-dried syngas furthercontaining H₂ and CO.
 34. The process according to claim 19, wherein thefeed gas is an optionally pre-treated Claus tail gas further containingN₂.
 35. A process for the conversion of H₂S to elemental sulphur,comprising the step of subjecting the second product gas as obtained inthe process according to claim 19, optionally after pre-drying, to aClaus process to obtain elemental sulphur and a tail gas comprising H₂Sequivalents and CO₂.
 36. The process according to claim 19, wherein thesecond product gas is subjected, optionally after pre-drying, to a Clausprocess to obtain elemental sulphur and a tail gas comprising H₂Sequivalents and CO₂, and the tail gas is used as feed gas in step (a) ofthe process according to claim 19, optionally after pre-drying.
 37. Asystem for performing the process according to claim 19, comprising: (A)a Claus unit comprising: (a1) a first inlet for receiving the secondproduct gas; (a5) a first outlet for discharging elemental sulphur; and(a6) a second outlet for discharging a Claus tail gas; and (B) anadsorption module comprising: (b1) a reactor bed comprising theadsorbent as defined in any one of claims 19, 23 and 24; (b2) a firstinlet for receiving the Claus tail gas; and (b4) a first outlet fordischarging the second product gas, wherein outlet (a6) is in fluidconnectivity with inlet (b2) and outlet (b4) is in fluid connectivitywith inlet (a1).
 38. A method for production of elemental sulphurcomprising subjecting a H₂S-enriched gas obtainable in step (b) of theprocess according to claim 19 to a Claus process.